Methods for continuously improving drilling and completions operations

ABSTRACT

Disclosed is a method for identifying opportunities for improvement in drilling and completions operations. At least one processor receives historical well data related to drilling and completions activities received from well monitoring sensors. The activities can include tripping, running casing, running bottom hole assembly, running riser, drilling connection operations, running screens, and running tubing. From the historical data, relative percentages of time spent on the activities are determined. Based on the relative time spent on each of the activities, a first priority activity is selected for improvement. A performance target for the first priority activity representing a value that can be calculated using well data received from the well monitoring sensors is determined. Real-time data is received from the well monitoring sensors. A current performance value using the real-time data is calculated and reviewed periodically to identify opportunities for improvement. Changes are implemented in an activity to improve the current performance value.

FIELD

The present disclosure relates to methods for continuously improving drilling and completions operations using automated activity analysis based on real-time data.

BACKGROUND

Tools exist within the oil and gas industry to automatically calculate drilling activities based on real-time data. However, the tools do not specify how to use them to continuously improve operations, specifically, turning information into actionable knowledge. This creates a scenario where each user develops their own ad-hoc process and procedures to use the information provided by the automatic calculation tools, and the benefits of consistency across crews, rigs, or projects are not achieved. Performance of a rig or well is no longer solely measured by the rate of penetration or days per well. As technology advances, rig sensor data is collected, aggregated, and broadcast around the world for various stakeholders to review. As this data becomes more available and visible there is a push to optimize every part of the drilling process. There exists a need for a method which collects and analyzes the Real time data in a way that focuses attention on drilling and completions activities that have been too cumbersome to measure consistently, allowing the rigs, wells and fleets of rigs to improve in the specific areas of focus.

SUMMARY

In one aspect, a method is provided for identifying opportunities for improvement in drilling and completions operations. At least one processor receives historical well data related to two or more drilling and completions activities received from a plurality of well monitoring sensors. The at least one processor then processes the historical data to determine relative percentages of time spent on the drilling and completions activities. Based on the relative time spent on each of the drilling and completions activities, a first priority activity of the drilling and completions activities is selected for improvement. A performance target representing a value that can be calculated using well data received from the plurality of well monitoring sensors for the first priority activity is determined. The at least one processor then receives real-time data from the plurality of well monitoring sensors. A current performance value using the real-time data is calculated and compared with the performance target. The current performance value is reviewed on a predetermined frequency to identify any opportunities for improvement in the first priority activity and/or to modify the performance target. Changes are implemented in an activity to improve the current performance value. Additional priority activities can similarly be later identified and targets determined for them.

DESCRIPTION OF THE DRAWINGS

These and other objects, features and advantages of the present invention will become better understood with reference to the following description, appended claims and accompanying drawings. The drawings are not considered limiting of the scope of the appended claims. The elements shown in the drawings are not necessarily to scale. Reference numerals designate like or corresponding, but not necessarily identical, elements.

FIG. 1 is a pie chart useful in a method according to one exemplary embodiment.

FIG. 2 is a histogram useful in a method according to one exemplary embodiment.

FIG. 3 is a flowchart illustrating a method according to one exemplary embodiment.

DETAILED DESCRIPTION

In one embodiment, at least one processor receives or collects historical well data related to two or more drilling and completions activities received from a plurality of well monitoring sensors. In some embodiments, e.g., for deep water drilling, the historical data includes data related to tripping activities for at least 1000 connections. In some embodiments, e.g., for land and shelf drilling, the historical data includes data related to drilling activities for at least one complete well. For tripping activities, a month of data collection may be required, while drilling may require more time to collect an adequate data set. A quality data set is dependent upon the number of activities the rig performed during the collection period.

The at least one processor processes the historical data to determine relative percentages of time spent on the drilling and completions activities. For example, the processor can generate a pie chart visually illustrating the percentages of time spent on certain drilling and completions activities for a well. Such drilling and completions activities include, but are not limited to, tripping, running casing, running bottom hole assembly, running riser, drilling connection operations, running screens, running tubing and the like. The top three activities can be tripping, drilling and circulating/wellbore conditioning. FIG. 1 is an example a pie chart that shows a break down of rig activities from a complete deep water well.

In one embodiment, the relative time spent on each of the drilling and completions activities is used to determine or select a first priority activity of the drilling and completions activities for improvement. In one embodiment, the activity to which the most time is devoted is selected as the first priority activity. In alternative embodiments, other factors are considered resulting in another activity being selected other than the activity to which the most time is devoted. Such factors can include any operational constraints, sustainability of the target, and safety and environmental considerations.

A performance target representing a value that can be calculated using well data received from the plurality of well monitoring sensors for the first priority activity is determined.

The well monitoring sensors can include sensors for measuring hole depth, bit depth, revolutions per minute, weight on bit, flow in, hook load, torque, block height and/or pump pressure. The sensors can be used for measuring slip to slip connection time during tripping operations, average pipe moving speed during tripping operations, and/or gross time per stand during tripping operations. The sensors can be used for measuring slip to slip connection time during casing operations, average pipe moving speed during casing operations, and/or gross time per stand during casing operations. The sensors can be used for measuring slip to slip connection time during bottom hole assembly operations and/or gross time per stand during bottom hole assembly operations. The sensors can be used for measuring time to run riser, time to pull riser, average riser moving speed during riser operations, and/or gross time per stand during riser operations. The sensors can be used for measuring slip to slip connection time during a weight to weight connection in drilling operations, gross time per stand during drilling operations, wellbore treatment time during a weight to weight connection in drilling operations, drilled distance, distance per stand drilled in rotary mode, and/or distance per stand drilled in sliding mode. The sensors can be used for measuring slip to slip connection time during screen running operations, average pipe moving speed during screen running operations, and/or gross time per stand during screen running operations. The sensors can be used for measuring slip to slip connection time during tubing running operations, average pipe moving speed during tubing running operations, and/or gross time per stand during tubing running operations.

The performance target is an improvement goal for the activity. The performance target can be any of many possible key performance indicators (KPIs) that represent drilling and completions operations. The following is a partial list, grouped by major activity type.

Tripping Key Performance Indicators

Tripping—Slip to Slip Connection Time [min] is the time spent in slips and making a connection during tripping operations. This KPI is also available separately for the running (RIH) and pulling (POOH) part of the run. Tripping—Average Pipe Moving Speed—CH [m/h, ft/h] is the average speed the pipe is moved during tripping in and out of the hole in cased hole. This KPI includes only the movement itself, the time in slips is excluded. Tripping—Average Pipe Moving Speed—OH [m/h, ft/h] is the average speed the pipe is moved during tripping in and out of the hole in open hole. This KPI includes only the movement itself, the time in slips is excluded. Tripping—Gross Time per Stand—CH [min] is the time needed for the pipe to be tripped in or out of the cased hole as a combination of pipe moving time and in slips time. This KPI is also available separately for the running (RIH) and pulling (POOH) part of the run. Tripping—Gross Time per Stand—OH [min] is the time needed for the pipe to be tripped in or out of the open hole as a combination of pipe moving time and in slips time. This KPI is also available separately for the running (RIH) and pulling (POOH) part of the run.

Running Casing Key Performance Indicators

Casing—Slip-to-Slip Connection Time [min] is the time spent in slips during running casing and/or liner (excluding the drill pipe). Casing—Average Pipe Moving Speed—CH [m/h, ft/h] is the average speed the joint is moved during running casing and/or liner (excluding the drill pipe) in the cased hole. Casing—Average Pipe Moving Speed—OH [m/h, ft/h] is the average speed the joint is moved during running casing and/or liner (excluding the drill pipe) in the open hole. Casing—Gross Time per Stand—CH [min] is the time needed for a joint to be run in the cased hole as a combination of pipe moving time and in slips time. Casing—Gross Time per Stand—OH [min] is the time needed for a joint to be run in the open hole as a combination of pipe moving time and in slips time. Casing—Gross Running Rate—CH [joints/h] is the rate for a joint to be run in the cased hole as a combination of pipe moving time and in slips time. Actually it is the Casing—Gross Running Speed divided by an average casing joint length of 12 meters. Casing—Gross Running Rate—OH [joints/h] is the rate for a joint to be run in the open hole as a combination of pipe moving time and in slips time. Actually it is the Casing—Gross Running Speed divided by an average casing joint length of 12 meters.

Running BHA Key Performance Indicators

BHA—Slip-to-Slip Connection Time [min] is the time spent in slips during running BHA. This KPI is also available separately for the running (RIH) and pulling (POOH) part of the run. BHA—Gross Time per Stand [min] is the time needed for a stand to be run in or out of the hole as a combination of pipe moving time and in slips time.

Running Riser Key Performance Indicators

Riser—Running Slip-to-Slip Connection Time [min] is the time spent in slips during running riser. Riser—Pulling Slip-to-Slip Connection Time [min] is the time spent in slips during pulling riser. Riser—Average Pipe Moving Speed [m/h, ft/h] is the average speed the joint is moved during running riser. Riser—Gross Time per Stand [min] is the time needed for a joint to be run in or out of the hole as a combination of pipe moving time and in slips time.

Drilling Connection Key Performance Indicators

Drilling—Weight to Slips Time [min] is only calculated during a weight to weight connection. This KPI starts when the bit is lifted off bottom and lasts until the drill string is in slips. It includes all time spent on reaming, washing, circulating, running in/out of hole and other operations during the defined time frame. Drilling—Slip to Slip Connection Time [min] is the time spent in slips during a weight to weight connection. Drilling—Slips to Weight Time [min] is only calculated during a weight to weight connection. This KPI starts when the drill string is released out of the slips and lasts until the bit is on bottom drilling again. It includes all time spent on reaming, washing, circulating, running in/out of hole and other operations during the defined time frame. Drilling—Wellbore Treatment Time per Connection [min] is the total time spent on wellbore treatment (reaming up/down, washing up/down, and circulation) during a weight to weight connection. Drilling—Gross Time per Stand [min] is the total time needed for drilling one stand of pipe including the weight to weight connection. Actually it covers all time from the end of a weight to weight connection until the end of the subsequent one. Drilling—Net ROP per Stand [m/h, ft/h] is calculated by dividing the drilled distance for one stand of pipe with the Net Drilling Time per Stand KPI. Drilling—Wellbore Treatment Time per Stand [min] is the time spent on wellbore treatment (ream up/down, wash up/down and circulation) during drilling one stand of pipe excluding the weight to weight connection period for that stand. Drilling—Rotating Drilling Meterage per Stand [m, ft] is the distance per stand that was drilled in rotary mode. Drilling—Sliding Drilling Meterage per Stand [m, ft] is the distance per stand that was drilled in sliding mode.

Screen Key Performance Indicators

Screen—Slip-to-Slip Connection Time [min] is the time spent in slips during running screens (excluding the drill pipe). Screen—Average Pipe Moving Speed—CH [m/h, ft/h] is the average speed the joint is moved during running screens (excluding the drill pipe) in the cased hole. Screen—Average Pipe Moving Speed—OH [m/h, ft/h] is the average speed the joint is moved during running screens (excluding the drill pipe) in the open hole. Screen—Gross Time per Stand—CH [min] is the time needed for a joint to be run in the cased hole as a combination of pipe moving time and in slips time. Screen—Gross Time per Stand—OH [min] is the time needed for a joint to be run in the open hole as a combination of pipe moving time and in slips time.

Tubing Key Performance Indicators

Tubing—Slip-to-Slip Connection Time [min] is the time spent in slips and making a connection during running tubing. Tubing—Pulling Slip-to-Slip Connection Time [min] is the time spent in slips and making a connection during pulling tubing. Tubing—Average Pipe Moving Speed [m/h, ft/h] is the average speed the joint is moved during running tubing. Tubing—Gross Time per Stand [min] is the time needed for a joint to be run in or out of the hole as a combination of pipe moving time and in slips time. Tubing—Gross Pulling Time per Stand [min] is the time needed for a joint to be pulled out of the hole as a combination of pipe moving time and in slips time.

When the performance target is a value measured in time, the performance target can represent the 10th percentile, also referred to as the P10 value. In other words, the performance goal is to consistently achieve the lowest 10% of times from the historical data. FIG. 2 is an example histogram for Tripping—Slip-to-Slip Connection Time. The P10 is 1.48 minutes and the P50 is 1.98 minutes. A good initial target for this KPI is 2 minutes per connection.

When the value is a measure of speed for distance, the performance target can represent the 90th percentile, also referred to as the P90 value. In other words, the performance goal is to consistently achieve the highest 90% of speeds or distances from the historical data. In one embodiment, the performance target for the first priority activity is determined as best performance for the first priority activity based on the historical data. In some embodiments, the current performance is dramatically different from the P10 or P90 value, and in such cases, a more moderate, intermediate goal can be determined as the performance target.

In one embodiment, a baseline value for the first priority activity is determined as the 50th percentile for the first priority activity based on the historical data.

Once the performance target is set and the baseline value is determined for the first priority activity, the at least one processor receives real-time data from the plurality of well monitoring sensors during normal operations. The real-time data needed for the calculation of the value to compare with the performance target is collected and processed by the processor. A current performance value using the real-time data is then calculated and compared with the performance target. This calculation occurs on a predetermined frequency, preferably at least daily. The current performance value can then be reviewed on a predetermined frequency, i.e. daily. Drilling and completions personnel reviewing the current performance value can identify any opportunities for improvement in the first priority activity and/or to modify the performance target. Improvements can be made by identifying ways that, e.g., work processes and tasks can be completed with the least amount of motion, tools or materials can be placed in easy-to-grasp positions, and steps that do not add value to the task being performed can be eliminated.

Suitable software applications to collect and analyze well data for use in the method, also referred to as real time benchmarking software packages, include proNova web application available from Thonhauser Data Engineering (TDE) GmbH (Leoben, Austria), and logging services available from Sperry Drilling (a Halliburton company), Baker-Hughes, and Geoservices (a Schlumberger Limited company).

In one embodiment, a daily report is generated including the current performance value, the baseline value and the performance target. A plot can be generated including current performance values, the baseline value and the performance target on a predefined frequency between daily and up to one month and six months, even between one month and six months.

The plot can be communicated with drilling and completions personnel that may include business managers, operation superintendents, drilling engineers, drilling site managers, field drilling engineers, rig managers, operators and any of the rig's performance team.

In one embodiment, once the performance relative to the first performance target has been established, a second priority activity can be identified and a second performance target determined for the second priority activity. In one embodiment, the method further includes receiving by the at least one processor real-time data from the plurality of well monitoring sensors, calculating, using the at least one processor, a second current performance value using real-time data to compare to the second performance target, and reviewing the second current performance value on a predetermined frequency to identify opportunities for improvement in the second priority activity and/or to modify the second performance target. Additional priority activities can similarly be identified and targets determined for them.

In one embodiment, reports are generated on a daily basis and shared with personnel. Additional reports including plots can be generated monthly, quarterly or on any other desired frequency and shared with personnel. Appropriate personnel can include of business managers, operation superintendents, drilling engineers, drilling site managers, field drilling engineers, rig managers and operators.

The drilling and completions activities can include tripping operations, running casing, running bottom hole assembly, running riser, drilling connection operations, running screens, running tubing and combinations thereof.

In one embodiment, the performance target is determined for a plurality of wells, i.e., two or more, and the method further includes separately calculating the current performance value for each of the plurality of wells. The current performance value of the multiple wells can then be compared on a predetermined frequency. As a result of reviewing such comparisons, personnel can identify opportunities for improvement in the first priority activity and/or modifying the performance target for any of the wells.

Daily improvement with respect to the performance targets can include, for example, receiving the processed data from a drilling activity calculation tool in a processor on a daily basis, reviewing the prior day's results, and assessing a rig crew's performance relative to the target. Once the crew is consistently reaching the target, the target can be moved closer to the benchmark or the most desired value. Once the benchmark is reached, the target can stay in place so that performance becomes a learned behavior, and the rig can move on to another relevant performance target. Reports can include capturing lessons learned and best practices for steps used to achieve performance improvements, and share these lessons learned and best practices with other crews, rigs and the like so that the improvements seen on one rig can be realized more broadly.

In one embodiment, the periodic report compares the current performance target to the baseline average performance. From this data, time savings can be calculated and, with a spread rate, a dollar value for savings can be reported. The calculation used to determine the dollar value created by this workflow is as follows:

(baseline KPI average−daily KPI average)*daily KPI count*spread rate per minute=daily savings

This calculation is completed for each day in the period and summed to obtain the total savings in the period. If the daily average is greater than the prior average, there will be a negative daily savings. This means on that particular day the rig performed worse than their baseline average. It is expected that a rig will have an average that is worse than the baseline average during uncommon rig activities. The uncommon rig activity days need not be focused on if the monthly average is still improving.

In one embodiment, as more rigs in a fleet start monitoring performance against performance targets, it is best to complete this activity in one system allowing the fleet performance to be easily monitored. Monitoring fleet performance can help identify underperforming rigs, and it can also be used to compare different tools or service companies' performance during specific operations. In addition, rig comparisons can be used to make financial business decisions by management.

FIG. 3 is a flowchart illustrating a method according to one embodiment. In step 101, at least one processor receives historical well data related to two or more drilling and completions activities received from the plurality of well monitoring sensors. In step 102, the at least one processor processes the historical data to determine relative percentages of time spent on the drilling and completions activities. In step 103, based on the relative time spent on each of the drilling and completions activities, a first priority activity of the drilling and completions activities is selected for improvement. In step 104, a performance target representing a value that can be calculated using well data received from the plurality of well monitoring sensors for the first priority activity is determined. In step 105, the at least one processor receives real-time data from the plurality of well monitoring sensors. In step 106, a current performance value using the real-time data is calculated and compared with the performance target. In step 107, the current performance value is reviewed on a predetermined frequency to identify any opportunities for improvement in the first priority activity and/or to modify the performance target. In step 108, changes are implemented in an activity to improve the current performance value. Performance is reviewed as a result of the changes and additional opportunities for improvement are identified.

For the purposes of this specification and appended claims, unless otherwise indicated, all numbers expressing quantities, percentages or proportions, and other numerical values used in the specification and claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that can vary depending upon the desired properties sought to be obtained by the present invention. It is noted that, as used in this specification and the appended claims, the singular forms “a,” “an,” and “the,” include plural references unless expressly and unequivocally limited to one referent.

Unless otherwise specified, the recitation of a genus of elements, materials or other components, from which an individual component or mixture of components can be selected, is intended to include all possible sub-generic combinations of the listed components and mixtures thereof. Also, “comprise,” “include” and its variants, are intended to be non-limiting, such that recitation of items in a list is not to the exclusion of other like items that may also be useful in the materials, compositions, methods and systems of this invention.

This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to make and use the invention. The patentable scope is defined by the claims, and can include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. All citations referred herein are expressly incorporated herein by reference.

From the above description, those skilled in the art will perceive improvements, changes and modifications, which are intended to be covered by the appended claims. 

What is claimed is:
 1. A method for identifying opportunities for improvement in drilling and completions operations comprising: a. receiving by at least one processor historical data comprising well data related to two or more drilling and completions activities received from a plurality of well monitoring sensors; b. processing, using the at least one processor, the historical data to determine relative percentage of time spent on the drilling and completions activities; c. selecting a first priority activity of the drilling and completions activities for improvement based on the relative time spent on each of the drilling and completions activities; d. determining a performance target for the first priority activity wherein the performance target represents a value that can be calculated using well data received from the plurality of well monitoring sensors; e. receiving by the at least one processor real-time data from the plurality of well monitoring sensors; f. calculating, using the at least one processor, a current performance value using the real-time data to compare to the performance target; g. reviewing the current performance value on a predetermined frequency to identify opportunities for improvement in the first priority activity and/or to modify the performance target; and h. implementing a change in at least one of the drilling and completions activities to improve the current performance value.
 2. The method of claim 1, wherein the drilling and completions activities are selected from the group consisting of tripping operations, running casing, running bottom hole assembly, running riser, drilling connection operations, running screens, running tubing and combinations thereof.
 3. The method of claim 1, wherein the plurality of well monitoring sensors include sensors for measuring hole depth, bit depth, revolutions per minute, weight on bit, flow in, hook load, torque, block height and/or pump pressure.
 4. The method of claim 1, wherein the performance target is selected from slip to slip connection time during tripping operations, average pipe moving speed during tripping operations, and/or gross time per stand during tripping operations.
 5. The method of claim 1, wherein the performance target is selected from slip to slip connection time during casing operations, average pipe moving speed during casing operations, and/or gross time per stand during casing operations.
 6. The method of claim 1, wherein the performance target is selected from slip to slip connection time during bottom hole assembly operations and/or gross time per stand during bottom hole assembly operations.
 7. The method of claim 1, wherein the performance target is selected from time to run riser, time to pull riser, average riser moving speed during riser operations, and/or gross time per stand during riser operations.
 8. The method of claim 1, wherein the performance target is selected from slip to slip connection time during a weight to weight connection in drilling operations, gross time per stand during drilling operations, wellbore treatment time during a weight to weight connection in drilling operations, drilled distance, distance per stand drilled in rotary mode, and/or distance per stand drilled in sliding mode.
 9. The method of claim 1, wherein the performance target is selected from slip to slip connection time during screen running operations, average pipe moving speed during screen running operations, and/or gross time per stand during screen running operations.
 10. The method of claim 1, wherein the performance target is selected from slip to slip connection time during tubing running operations, average pipe moving speed during tubing running operations, and/or gross time per stand during tubing running operations.
 11. The method of claim 1, wherein the drilling and completions activity determined to have the highest relative percentage of time spent is selected as the first priority activity.
 12. The method of claim 1, wherein the first priority activity selected is measured in time; and the performance target for the first priority activity is determined as the 10^(th) percentile for the first priority activity based on the historical data.
 13. The method of claim 1, wherein the first priority activity is a speed; and the performance target for the first priority activity is determined as the 90^(th) percentile for the first priority activity based on the historical data.
 14. The method of claim 1, wherein the performance target for the first priority activity is determined as best performance for the first priority activity based on the historical data.
 15. The method of claim 1, wherein a baseline value for the first priority activity is determined as the 50^(th) percentile for the first priority activity based on the historical data.
 16. The method of claim 15, further comprising generating a daily report comprising the current performance value, the baseline value and the performance target.
 17. The method of claim 16, further comprising communicating the daily report with drilling and completions personnel selected from the group consisting of business managers, operation superintendents, drilling engineers, drilling site managers, field drilling engineers, rig managers and operators.
 18. The method of claim 15, further comprising generating a plot comprising current performance values, the baseline value and the performance target on a predefined frequency between one month and six months.
 19. The method of claim 18, further comprising communicating the plot with drilling and completions personnel selected from the group consisting of business managers, operation superintendents, drilling engineers, drilling site managers, field drilling engineers, rig managers and operators.
 20. The method of claim 1, wherein the historical data comprises data related to tripping activities for at least 1000 connections.
 21. The method of claim 1, wherein the historical data comprises data related to drilling activities for at least one complete well.
 22. The method of claim 1, wherein the performance target is determined for a plurality of wells and further comprising: separately calculating the current performance value for each of the plurality of wells; comparing the current performance value of the plurality of wells on a predetermined frequency; and identifying opportunities for improvement in the first priority activity and/or modifying the performance target for any of the plurality of wells.
 23. The method of claim 1, further comprising: determining the that the performance target has been achieved; selecting a second priority activity of the drilling and completions activities for improvement; determining a second performance target for the second priority activity wherein the second performance target represents a second value that can be calculated using well data received from the plurality of well monitoring sensors; receiving by the at least one processor real-time data from the plurality of well monitoring sensors; calculating, using the at least one processor, a second current performance value using the real-time data to compare to the second performance target; and reviewing the second current performance value on a predetermined frequency to identify opportunities for improvement in the second priority activity and/or to modify the second performance target. 